Cold Heavy Oil Production System and Methods

ABSTRACT

A system for producing hydrocarbons and sand from a formation includes a wellbore having a substantially horizontal portion. In addition, the system includes a liner disposed in the substantially horizontal portion. The liner has a longitudinal axis and includes a plurality of slots. Each slot is configured to pass sand from the formation into the wellbore. Further, the system includes a production string extending through the wellbore. Still further, the system includes a pump disposed at a downhole end of the production string in the liner. The pump has a central axis, an outlet coupled to the downhole end of the production tubing, and an inlet distal the production string. The pump is configured to pump hydrocarbons and sand from the formation to the surface. The central axis of the pump is oriented at an angle α measured downward from vertical. The angle α is between 60° and 90°.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. provisional patent applicationSer. No. 61/624,053 filed Apr. 13, 2012, and entitled “Cold Heavy OilProduction System and Methods,” which is hereby incorporated herein byreference in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

The disclosure relates generally to systems and methods for recoveringsubterranean hydrocarbons. More particularly, the disclosure relates tosystems and methods for cold heavy oil production with sand in ahorizontal or deviated wellbore.

Unconventional sources of oil, such as oil shales, oil sands and heavyoil contain unique physical properties that require particularizedsystems, techniques and procedures to allow for their effective andeconomic extraction and production. For instance, heavy oil has arelatively high density and viscosity, which present recovery challengesas it is more resistant to flow than lighter crude oils. Challengesassociated with resistance to flow may be even greater in cold weatherapplications, such as production systems targeting recovery of heavy oilfrom reservoirs in Canada and Alaska. However, while unconventional oilsupplies like heavy oil present unique challenges, rapidly dwindlingsupplies of traditional sources of oil have made the production ofunconventional oil sources, such as heavy oil, more economicallyattractive.

In general, heavy oil may be extracted using primary, secondary,tertiary or mining methods. Primary extraction methods, also referred toas “cold production,” rely on natural forces within the formation, suchas pressure generated by a proximal gas cap or gravity drainage, etc.,to produce heavy oil from a subterranean formation. One particular formof primary extraction is cold heavy oil production with sand (CHOPS).CHOPS is similar to techniques used for extracting traditional sourcesof oil, with one significant deviation being that sand is produced fromthe reservoir along with the heavy oil. The production of sand from thewell using the CHOPS method allows for the creation of “worm holes” inthe formation proximal the wellbore. These worm holes act as conduitsfor the production of more sand and oil into the wellbore, which may bepumped to the surface for recovery. Secondary methods often involve theuse of injecting materials into the well in order to enhance production,such as through injecting water, natural gas or carbon dioxide into thewell. Tertiary methods, such as steam assisted gravity drainage (SAGD),often involve heating the heavy oil through injecting high temperaturesteam into the well in an effort to lower the viscosity of the oil andenhance the mobility of the oil such that it may more easily be producedfrom the formation.

Secondary and tertiary methods, while effective in some instances forrecovering heavy oil, may have several disadvantages with respect toprimary or cold production methods. For instance, secondary and tertiarymethods often have an increased cost due to their reliance on injectingadditional materials and energy into the well, such as water, naturalgas and steam. Injecting additional material into the well may also beundesirable. While primary recovery methods, such as CHOPS, may not facethese particular issues, they may have other drawbacks, such as lowerrecovery rates. For instance, CHOPS performed on a vertical wellbore maybe limited in production due to the vertical well having less thanoptimal exposure to the oil producing formation.

BRIEF SUMMARY OF THE DISCLOSURE

These and other needs in the art are addressed in one embodiment by asystem for producing hydrocarbons and sand from a formation. In anembodiment, the system comprises a wellbore having a substantiallyhorizontal portion traversing the formation. In addition, the systemcomprises a liner disposed in the substantially horizontal portion ofthe wellbore. The liner has a longitudinal axis and includes a pluralityof slots. Each slot is configured to pass sand from the formation intothe wellbore. Further, the system comprises a production stringextending through the wellbore. Still further, the system comprises apump disposed at a downhole end of the production string and disposed inthe liner. The pump has a central axis, an outlet coupled to thedownhole end of the production tubing, and an inlet distal theproduction string. The pump is configured to pump hydrocarbons and sandfrom the formation to the surface. The central axis of the pump isoriented at an angle α measured downward from vertical. The angle α isbetween 60° and 90°.

These and other needs in the art are addressed in another embodiment bya system for producing hydrocarbons and sand from a formation. In anembodiment, the system comprises a wellbore having a substantiallyhorizontal portion traversing the formation. In addition, the systemcomprises a liner disposed in the substantially horizontal portion ofthe wellbore. The liner has a longitudinal axis and includes a pluralityof slots. Further, the system comprises a production string disposed inthe wellbore. Still further, the system comprises a pump having anoutlet end coupled to a downhole end of the production string and aninlet end distal the production string. The pump is disposed in theliner and is configured to pump sand and hydrocarbons through theproduction string to the surface. Moreover, the system comprises atailpipe coupled to the inlet end of the pump and disposed in the liner.The tailpipe is configured to flow sand and hydrocarbons to the pump.

These and other needs in the art are addressed in another embodiment bya method for producing hydrocarbons from a wellbore having asubstantially horizontal portion traversing a formation comprising sand.In an embodiment, the method comprises (a) determining a maximum grainsize of the sand in the formation. In addition, the method comprises (b)inserting a liner into the substantially horizontal portion of thewellbore. The liner has a longitudinal axis and a plurality ofcircumferentially spaced elongate slots. Each slot is oriented parallelto the longitudinal axis and has a width that is at least 95% of themaximum grain size of the sand. Further, the method comprises (c)coupling a tailpipe to an inlet end of a pump. Still further, the methodcomprises (d) coupling a production string to an outlet end of the pump.Moreover, the method comprises (e) positioning the pump and the conduitin the liner after (d).

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of the preferred embodiments of thedisclosure, reference will now be made to the accompanying drawings inwhich:

FIG. 1 is a schematic, cross-sectional view of an embodiment of a coldheavy oil production system in accordance with the principles describedherein;

FIG. 2 is a top view of a segment of the production liner of the systemof FIG. 1;

FIG. 3 is a schematic, cross-sectional view of an embodiment of a coldheavy oil production system in accordance with the principles describedherein; and

FIG. 4 is a schematic, cross-sectional view of the downhole section ofthe system of FIG. 3.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

The following discussion is directed to various exemplary embodiments.However, one skilled in the art will understand that the examplesdisclosed herein have broad application, and that the discussion of anyembodiment is meant only to be exemplary of that embodiment, and notintended to suggest that the scope of the disclosure, including theclaims, is limited to that embodiment.

Certain terms are used throughout the following description and claimsto refer to particular features or components. As one skilled in the artwill appreciate, different persons may refer to the same feature orcomponent by different names. This document does not intend todistinguish between components or features that differ in name but notfunction. The drawing figures are not necessarily to scale. Certainfeatures and components herein may be shown exaggerated in scale or insomewhat schematic form and some details of conventional elements maynot be shown in interest of clarity and conciseness.

In the following discussion and in the claims, the terms “including” and“comprising” are used in an open-ended fashion, and thus should beinterpreted to mean “including, but not limited to . . . .” Also, theterm “couple” or “couples” is intended to mean either an indirect ordirect connection. Thus, if a first device couples to a second device,that connection may be through a direct connection of the two devices,or through an indirect connection via other intermediate devices,components, and connections. In addition, as used herein, the terms“axial” and “axially” generally mean along or parallel to a central axis(e.g., central axis of a body or a port), while the terms “radial” and“radially” generally mean perpendicular to the given axis. For instance,an axial distance refers to a distance measured along or parallel to theaxis, and a radial distance means a distance measured perpendicular tothe axis. The term “heavy crude oil” or “heavy oil” is intended to meanany type of oil or oil source that does not flow easily.

Systems and methods for producing hydrocarbons are disclosed herein.Embodiments described herein can be employed in various hydrocarbonproduction applications, but are particularly suited for producing coldheavy oil with sand from a horizontal or deviated wellbore.

Referring now to FIG. 1, an embodiment of a cold heavy oil productionsystem 10 is shown. In this embodiment, system 10 generally comprises awellbore 11 extending from a wellhead 12 disposed at the surface 2 andpenetrating a subterranean formation 3, a “Christmas tree” or productionmanifold 13 coupled to wellhead 12, and a production string 14 extendingfrom the surface 2 through at least a portion of wellbore 11.

Subterranean formation 3 comprises heavy oil and a layer of permafrost 4extending from the surface 2 to a certain depth within the formation 3.Permafrost 4 comprises soil or other formation material at or below thefreezing point of water (32° F./0° C.). Permafrost 4 may contain ice,depending on the composition of the formation 3. In some applications,the layer of permafrost 4 in the formation 3 may extend at least severalhundred feet vertically from the surface 2.

In this embodiment, wellbore 11 includes a substantially verticalsection 11 a extending from the surface 2 to an elbow or kickoff point11 b disposed vertically below permafrost 4. Wellbore 11 also includes ahorizontal or deviated section 11 c having an approximate doglegseverity of less than 5° per 100 feet and extending from kickoff point11 b to a terminus or toe 11 d. Casing 15 extends from wellhead 12through vertical section 11 a of wellbore 11, and a liner 16 extendsthrough deviated section 11 c of wellbore 11. An annulus 17 extendsthrough wellbore 11 and is disposed about string 14. As will bedescribed in more detail below, liner 16 includes a plurality ofcircumferentially and axially spaced slots or perforations that allowfluid communication between wellbore 11 and formation 3.

Manifold 13 is coupled to wellhead 12 and seals wellbore 11 from thesurrounding environment at the surface 2. Manifold 13 includes aplurality of valves, spools and other equipment for controlling andregulating the flow of fluids from wellbore 11 through production string14.

Production string 14 is an elongate tubular with has an uphole end 14 acoupled to manifold 13 at wellhead 12 and a downhole end 14 b indeviated section 11 c. String 14 functions as a conduit for transportingmaterials produced from formation 3 through wellbore 11 to manifold 13.In general, production string 14 can comprise any tubular for producingfluids to the surface, however, in this embodiment, production string 14is coiled tubing. A pump 18 is disposed at downhole end 14 b of string14. In particular, pump 18 has a first or uphole end 18 a coupled to end14 b of string 14 and a second or downhole end 18 b distal end 14 b.Downhole end 18 b of pump 18 includes an opening to provide fluidcommunication between wellbore 11 and production string 14. Pump 18transports sand and hydrocarbons through string 14 to manifold 13. Inthis embodiment, pump 18 is a progressive cavity pump having a downholestator and a rotor driven by a rod. Pump 18 is oriented at aninclination angle α measured downward from vertical. In embodimentsdescribed herein, inclination angle α is preferably between 60° and 90°,more preferably between 70° and 80°, and even more preferably about 75°.

Referring now to FIG. 2, a segment of liner 16 is shown. In thisembodiment, liner 16 has a longitudinal axis 26 and a plurality ofcircumferentially and axially spaced elongate slots 28 extendingradially therethrough (i.e., slots 28 extend radially from the outersurface of liner 16 to the inner surface of liner 16). Slots 28 definepassages through liner 16 and establish fluid communication betweenformation 3 and annulus 17.

In this embodiment, each slot 28 is rectangular—each slot 28 extendsalong a linear longitudinal axis between a first end 29 and a second end30. In addition, in this embodiment, each slot 28 is oriented parallelto axis 26 of liner 16. In other words, the longitudinal axis of eachslot 28 is oriented parallel to axis 26. Each slot 28 has a length L₂₈measured between ends 29, 30 and a width W₂₈ measured circumferentiallybetween the lateral sides of slot 28. Length L₂₈ is preferably between2.0 in. and 4.0 in. Further, the number and size of slots 28 ispreferably selected such that slots 28 define 3% of the outside surfacearea of liner 16.

The width W₂₈ of slots 28 is preferably sized to allow the flow of sandtherethrough from formation 3 into annulus 17. In general, formation 3includes a population of sand grains having sizes/diameters that varyacross a statistical distribution. The sand grain diameters can becharacterized based on their positions along the distribution rangingfrom the smallest to the largest grain sizes in formation 3, where forexample, diameter D₅₀ represent the median sand grain diameter of thedistribution (i.e., sand grains having a diameter right in the middle ofthe distribution of sand grain sizes in formation 3), diameter D₄₀represents the sand grain diameter at the 40^(th) percentile of thedistribution (i.e., sand grains having a diameter greater than 40% ofthe sand grains in formation 3), diameter D₉₀ represents the sand graindiameter at the 90^(th) percentile of the distribution (i.e., sandgrains having a diameter greater than 90% of the sand grains information 3), etc. The degree of uniformity or “sorting” of thediameters of the sand grains that makeup formation 3 can be determinedvia calculating a uniformity coefficient of formation 3, sometimesdefined as the ratio of the sand grain diameter at the 40th percentileof all sand grains of formation 3 over the sand grain diameter at the90th percentile of all sand grains (i.e., D₄₀/D₉₀). The sand grainsizing, statistical distribution, and uniformity parameters can bedetermined by obtaining and analyzing one or more core samples of sandgrains from formation 3. For instance, a core sample of the formation 3may be procured and a particle analysis can be performed on the coresample.

In the exemplary embodiment of FIG. 2, the width W₂₈ of slots 28 ispreferably selected such that each slot 28 is wider than the width of95% of the sand particles in the formation 3 (i.e., the width W₂₈ ispreferably greater than diameter D₉₅ of the sand grains at the 95^(th)percentile of the distribution). In other embodiments, slots 28 may besized such that they are greater than the width of 75% of the sandparticles in the formation 3 (i.e., diameter D₇₅). For most formations,the width W₂₈ of slots 28 preferably ranges between 0.010″-0.150″, andin this embodiment, width W₂₈ of slots 28 is 0.125″. In otherembodiments, slots 28 may have a different cross-sectional shape, suchas circular, triangular, etc., that are configured to allow the passageof sand particles through the slot having a size greater than 95% of thesand in the formation 3.

Liner 16 has an internal diameter (ID) configured to allow for thepassage of sand within wellbore 11 from formation 3 without forming ablockage therein. For most applications, liner 16 preferably has an IDbetween 5.0″ and 7.0″, however, in this embodiment, liner 16 has an IDof 6.125″ and an outer diameter (OD) of 7″. The ID of liner 16 may besized so as to allow flow of sand containing fluid in a horizontalflowpath. A larger diameter ID of liner 16 allows for sand to accumulateon the bottom of the liner 16 without resulting in a blockage ofwellbore 11 as material is allowed to flow over the accumulated sand.

Referring now to FIGS. 3 and 4, another embodiment heavy oil productionsystem 10′ is shown. System 10′ is substantially the same as system 10previously described except that system 10′ includes a tailpipe 20extending from pump 18 through deviated portion 11 c of wellbore 11.Tailpipe 20 has a first or uphole end 20 a coupled to pump 18 and asecond or downhole end 20 b distal pump 18. Downhole end 20 b is open,thereby defining an intake 21. In this embodiment, intake 21 of tailpipe20 is disposed at the vertically deepest section of wellbore 11 and isoriented at an angle β measured upward from vertical. In other words,the central axis of tailpipe 20 at intake 21 is oriented at angle βmeasured upward from vertical. To help ensure intake 21 of tailpipe 20is positioned proximal the first sump of wellbore 11 (i.e., low spotalong the substantially horizontal section 11 c where sand is mostlikely to collect), tailpipe 20 is advanced through substantiallyhorizontal section 11 c until angle β is preferably 85° to 90°, morepreferably 89° to 90°, and even more preferably as close to 90° aspossible. In addition, tailpipe 20 includes a slotted joint 20 c (FIG.4) that is about 30 feet in length and positioned proximal uphole end 20a. In this embodiment, the slots in slotted joint 20 c are oriented andshaped the same as slots 28 previously described, but preferably have acircumferential width greater than width W₂₈ of slots 28. Slotted joint20 c in tailpipe 20 allows for increased fluid flow area into string 14to allow for continued fluid flow into tailpipe 20 in the event thatintake 18 of tailpipe 20 becomes plugged due to the production of largesand-influxes. In order to mitigate the chance of the creation of flowblockages into tailpipe 20, tailpipe 20 and/or liner 16 are preferablysized such that approximately 0.75 in. of clearance is provided betweenthe outer surface of tailpipe 20 and the inner surface of liner 16.

Pump 18 pumps sand and hydrocarbon containing materials through tailpipe20 and production string 14 to wellhead 12 and manifold 13. Since sandflowing through string 14 may be abrasive, the inner surface of string14 is preferably treated or lined with an erosion resistive material,such as high density polyethylene (HDPE) or the like.

Referring still to FIGS. 3 and 4, in this embodiment, production string14 includes a heat trace 30 and a chemical injection line 31. Heat trace30 transfer thermal energy (i.e., heat) to production string 14, whichin turn transfers thermal energy to fluids flowing through string 14. Inthis embodiment, heat trace 30 is coupled to the outer surface ofproduction string 14 and extends longitudinally thereon from an upperend 30 a at the surface 2 to a terminal lower end 30 b proximal thebottom of the permafrost 4. Thus, heat trace 30 extends substantiallythrough permafrost 4, thereby at least partially offsetting any heattransfer from fluid within production string 14 to permafrost 4. Ingeneral, heat trace 30 can comprise any thermal energy producingelectrical conductor known in the art.

Chemical injection line 31 supplies and injects chemicals into adownhole segment of string 14. In this embodiment, line 31 is coupled tothe outer surface of string 14 and extends longitudinally along string14 from an upper end 31 a at the surface 2 to a lower chemical injectionpoint 31 b positioned proximal pump 18 (e.g, immediately uphole of pump18). Injection point 31 b is positioned to inject a chemical intoproduction string 14, such as a diluent(s) or other chemicals known inthe art to reduce the viscosity of hydrocarbons (e.g., viscous or heavyoil) flowing through string 14. By reducing the viscosity of fluidwithin production string 14, it can be more easily and effectivelytransported to the surface 2. It should be appreciated that otherchemicals can be injected at injection point 31 b to affect otherphysical or chemical properties of materials disposed within productionstring 14. Although injection point 31 b is positioned along string 14adjacent pump 18 in this embodiment, in other embodiments, the injectionpoint (e.g., injection point 31 b) can be positioned at other locationssuch as along the tailpipe (e.g., tailpipe 20).

Referring still to FIG. 4, in this embodiment, production string 14 alsoincludes a sump pressure sensor 25 a disposed proximal to the intake 21of tailpipe 20, a discharge pressure sensor 25 b disposed proximal tothe discharge end of pump 18, and an annulus pressure sensor 25 c isdisposed proximal to discharge pressure sensor 25 b and pump 18. Sumppressure sensor 25 a is coupled to tailpipe 20, and continuouslymeasures and communicates (to the surface 2) the fluid pressure atintake 21. Discharge pressure sensor 25 b is coupled to productionstring 14, and continuously measures and communicates (to the surface 2)the pressure of fluid exiting pump 18. Annulus pressure sensor 25 c iscoupled to production string 14, and continuously measures andcommunicates (to the surface 2) the pressure of fluid within wellbore 11just uphole of pump 18. Pressure measurements from discharge pressuresensor 25 b inform an operator of system 10 whether pump 18 isover-pressured with respect to its maximum operating discharge pressure.Annulus pressure sensor 25 c and sump pressure sensor 25 a are used byan operator of system 10 to determine if gas is entering wellbore 11from the formation 3 or if a blockage of sand has been formed withinwellbore 11 between pressure sensor 25 c and pressure sensor 25 a. Forinstance, pressure measurements from sensors 25 c, 25 a can be comparedto the hydrostatic pressure that is expected to exist at thoseparticular vertical depths in wellbore 11 given the average compositionof material within wellbore 11 (e.g., sand, water and oil). If pressuremeasurements from sensors 25 c, 25 a drop below that hydrostaticpressure, then gas may be being produced into wellbore 11. If thepressure measurement of sensor 25 c is higher than the hydrostaticpressure, then sand may be building up within wellbore 11 above sensor25 c, due to the relatively higher density of sand versus liquidhydrocarbon containing materials. Also, the differential pressure acrosspump 18 (i.e., difference in pressure readings between sensor 25 b andsensor 25 a) can be monitored in conjunction with the amount of torquebeing applied to the rotor of pump 18. For instance, a higherdifferential pressure across pump 18 and an increase in torque appliedagainst the rotor of pump 18 by materials being displaced through thepump may be indicative of a sand blockage.

Pump 18 is positioned deep in the deviated section 11 c of wellbore 11at angle α as previously described. Tailpipe 20 extends from the intakeof pump 18 to intake 21. Intake 21 is disposed at the vertically deepestsection of wellbore 11 at toe 11 d and at an angle β as previouslydescribed.

Liner 16 is disposed in the deviated portion 11 c of wellbore 11. Next,pump 18 and tailpipe 20 are positioned below the most uphole slots 28within liner 16, such that sand displaced into wellbore 11 from the mostuphole slots 28 within liner 16 can flow downhole through wellbore 11before entering slotted joint 20 c and/or intake 21 at second end 20 b.In this embodiment, pump 18 is positioned proximal the most uphole slots28 of liner 16. In addition, in this embodiment, the axial orlongitudinal distance of tailpipe 20 is approximately 300 feet, andthus, sand or other materials entering the most uphole slots 28 of liner16 must travel at least 300 feet before entering intake 21. In otherembodiments, pump 18 can be positioned longitudinally uphole of the mostuphole slots 28 of liner 16.

Referring still to FIG. 4, a counter-weighted sub 35 is positioned alongtailpipe 20 adjacent to and immediately downhole from pump 18. Sub 35includes at least one exhaust port 35 a coupled to a capillary tube 36extending from port 35 a to the expected operating fluid level in theannulus formed in wellbore 11 about string 14, where the expectedoperating level corresponds to the distance from the surface that fluidwithin wellbore 11 would be expected to rise to during production. Ports35 a and tube 36 allow gases flowing through tailpipe 20 to escape priorto entering pump 18. Sub 35 is counter-weighted such that it isconfigured to position exhaust ports 35 a on the high side of tail pipe20 (i.e., closer to the surface 2), which allows for more efficientseparation of the entrained gas. In this embodiment, the total flow areaprovided by ports 35 a is configured to allow entrained gas to escapewith less than 5.0 pounds per square inch (PSI) pressure drop. A tag-sub38 is also positioned along tailpipe 20 adjacent to and downhole fromsub 35 and is configured to allow for the proper space-out for the rotorof pump 18 and to allow for coiled tubing access from the surface 2 tothe tailpipe 20 and toe 11 d of wellbore 11. In this embodiment, tag-sub38 has a cylindrical tubular body with an inner diameter that is smallerthan the major diameter of the rotor, thereby preventing the rotor frompassing therethrough, but sufficiently large to allow coiled tubing topass therethrough.

While system 10′ is shown and described as including tailpipe 20, heattrace 30, chemical injection line 31, and counterweight sub 35, ingeneral, embodiments of cold heavy production systems in accordance withthe principles described herein need not include all of these featuresand may only include one or more in different combinations. Further, itmay be advantageous to provide one or more of these features in coldheavy production systems featuring a wellbore geometry that deviatesfrom the geometry of wellbore 11, which may arise in applications due toreservoir target step-out distance.

A method for producing cold heavy oil with sand from a horizontal ordeviated wellbore is provided herein. Referring to FIGS. 1 and 3,wellbore 11 is designed and drilled to include a substantially verticalportion 11 a and a horizontal or deviated portion 11 c as previouslydescribed. Once wellbore 11 has been extended from the surface 2 tokickoff point 11 b below permafrost 4, the deviated portion 11 c isdrilled with less than a 5° per 100 feet dogleg severity. In otherembodiments, horizontal or deviated portion 11 c is drilled with lessthan a 1-4° per 100 feet dogleg.

The substantially horizontal portion 11 c of wellbore 11 allows for thetransport of sand through wellbore 11 without a significant risk ofblockage. The deepest part of the deviated section 11 c of wellbore 11is drilled to no less than an 85° measured downward from vertical at thetoe 11 d. Liner 16 is installed in the deviated portion 11 c of thewellbore 11, with slots 28 configured to allow the passage of sand fromthe formation 3 to the wellbore 11, where the sand may be produced atleast 20% below the bubble point pressure of the formation fluid.Further, the ID of liner 16 is selected to maintain adequate velocity ofmaterial within wellbore 11 so that sand settles to less than ⅔ of ID ofliner 16 over the time it takes to travel longitudinally along the liner16. Transport correlations based on factors such as sand grain sizing offormation 3 and carrier fluid viscosity may be used in order todetermine the proper sizing of the ID of liner 16 to achieve the desiredfluid velocity within wellbore 11.

Production string 14 is advanced through wellbore 11 and pump 18 ispositioned in the portion of deviated section 11 c oriented at a 70° to80° inclination measured downward from vertical to enable thepositioning of pump 18 at angle α previously described. In addition,intake 21 of tailpipe 20 is positioned within the deepest portion ofwellbore 11 and proximal to or longitudinally downhole the most upholeset of slots 28 of liner 16.

In one exemplary embodiment, production through systems 10, 10′ isinitiated through recirculating oil through wellbore 11 and productionstring 14 to remove excess water, brine and other materials fromwellbore 11. Recirculation of fluid through wellbore 11 may continueuntil pressure measurements from sensors 25 a, 25 b, 25 c indicate thatoil is present within production string 14. Next, a “beanup” procedureis commenced to align grains of sand proximal to slots 28 in liner 16 soas to form wormholes within formation 3. As part of the beanupprocedure, the discharge pressure of pump 18, as measured by sensor 25b, is slowly increased to avoid collapsing wormholes in formation 3 or“slugging” sand into wellbore 11. In an embodiment, the differencebetween the static pressure of fluids in section 11 c proximal pump 18and tailpipe 20 (e.g., without any pumping) and the pressure at theintake of pump 18 during pumping operations, also known as the drawdownfrom pump 18, is increased by no more than 2.0 pounds per square inch(psi) per hour until significant sand influx into wellbore 11 fromformation 3 is noted from either sensors 25 a, 25 b, 25 c or detected atthe surface 2. The increase in drawdown can be accomplished by rotatinga rotor of pump 18 at a relatively higher speed in revolutions perminute (RPM). Once sand-cuts (i.e., the portion of the materialsdisplaced within production string 14 that is sand) from productionstring 14 exceed approximately 0.5%-1.0%, the drawdown rate of pump 18is held constant while maintaining adequate fluid velocity within string14 to help ensure adequate sand transport until sand-cuts from materialsproduced from production string 14 stabilize. Once sand-cuts havestabilized, drawdown may be increased, increasing the amount of materialproduced from production string 14. The process of maintaining thedrawdown rate relatively constant until sand-cut production hasstabilized is repeated until either (a) a maximum sand-cut of 15-25%,and more preferably 20%, is produced from string 14, or (b) equipmentlimits of sand-cut production have been reached.

In another embodiment, a slotted liner is provided including a pluralityof slots (similar in geometry as slots 28 of liner 16) having a widththat is approximately 1.3 times larger than the width of sand grainshaving a width that is greater than 95% of the sand grains disposed inthe reservoir. In that embodiment, the flow rate of fluid intoproduction string 14 is approximately 900 barrels per day per 1,000 feetof exposure in the reservoir at an approximate mobility of approximately1 millidarcy/centipoise (mD/cP). Further, if the desired rate ofhydrocarbon production of the well system is not satisfied at abottomhole pressure of approximately 20% below the bubble point pressureof the reservoir, sand production from the formation may be induced byusing rapid drawdown changes. For instance, drawdown changes greaterthan 40 psi per hour with hold periods may be used after a measurablesand-cut, such as 1%, is detected.

During production, a chemical, such as a diluent or other viscosityreducing agent, is preferably injected into string 14 at injection point31 b to enhance the flow of hydrocarbons therethrough. In addition, incases where wellbore 11 extends through permafrost 4, string 14 ispreferably heated with heat trace 30.

In the manner described, embodiments described herein reduce and/oreliminate the economic and environmental disadvantages of injectingmaterial and energy into the well in order to boost production. Further,embodiments described herein a particularly suited for horizontal ordeviated wellbores, which offer the potential for enhanced exposure tothe hydrocarbon containing formation.

While preferred embodiments have been shown and described, modificationsthereof can be made by one skilled in the art without departing from thescope or teachings herein. The embodiments described herein areexemplary only and are not limiting. Many variations and modificationsof the systems, apparatus, and processes described herein are possibleand are within the scope of the disclosure. Accordingly, the scope ofprotection is not limited to the embodiments described herein, but isonly limited by the claims that follow, the scope of which shall includeall equivalents of the subject matter of the claims. Unless expresslystated otherwise, the steps in a method claim may be performed in anyorder. The recitation of identifiers such as (a), (b), (c) or (1), (2),(3) before steps in a method claim are not intended to and do notspecify a particular order to the steps, but rather are used to simplysubsequent reference to such steps.

What is claimed is:
 1. A system for producing hydrocarbons and sand froma formation, the system comprising: a wellbore having a substantiallyhorizontal portion traversing the formation; a liner disposed in thesubstantially horizontal portion of the wellbore, the liner having alongitudinal axis and including a plurality of slots, wherein each slotis configured to pass sand from the formation into the wellbore; aproduction string extending through the wellbore; and a pump disposed ata downhole end of the production string and disposed in the liner,wherein the pump has a central axis, an outlet coupled to the downholeend of the production tubing, and an inlet distal the production string,wherein the pump is configured to pump hydrocarbons and sand from theformation to the surface; wherein the central axis of the pump isoriented at an angle α measured downward from vertical, wherein theangle α is between 60° and 90°.
 2. The system of claim A1, wherein theangle α is 75°.
 3. The system of claim 1, wherein each slot in the linerhas a circumferential width greater than a median size sand particle inthe formation.
 4. The system of claim 3, wherein the circumferentialwidth of each slot in the liner is greater than 95% of the sandparticles in the formation.
 5. The system of claim 1, wherein each slotin the liner has a length between 2.0 and 4.0 in.
 6. The system of claim1, wherein the plurality of slots in the liner comprises a first set ofcircumferentially spaced slots and a second set of circumferentiallyspaced slots axially spaced from the first set of slots; wherein thepump is axially positioned between the first set of slots and the secondset of slots.
 7. The system of claim 1, further comprising a heat tracecoupled to the production string, wherein the heat trace is configuredtransfer thermal energy to the production string.
 8. The system of claim1, further comprising a chemical injection line coupled to theproduction string, wherein the chemical injection line has a downholeinjection end positioned adjacent the outlet of the pump.
 9. A systemfor producing hydrocarbons and sand from a formation, the systemcomprising: a wellbore having a substantially horizontal portiontraversing the formation; a liner disposed in the substantiallyhorizontal portion of the wellbore, wherein the liner has a longitudinalaxis and includes a plurality of slots; a production string disposed inthe wellbore; a pump having an outlet end coupled to a downhole end ofthe production string and an inlet end distal the production string,wherein the pump is disposed in the liner and is configured to pump sandand hydrocarbons through the production string to the surface; and atailpipe coupled to the inlet end of the pump and disposed in the liner,wherein the tailpipe is configured to flow sand and hydrocarbons to thepump.
 10. The system of claim 9, wherein each slot in the liner has awidth greater than 95% of the particles of sand in the formation. 11.The system of claim 9, wherein each slot in the liner has a lengthbetween 2.0 and 4.0 in.
 12. The system of claim 9, wherein the pluralityof slots in the liner comprises a first set of circumferentially spacedslots and a second set of circumferentially spaced slots axially spacedfrom the first set of slots; wherein the pump is axially positionedbetween the first set of slots and the second set of slots.
 13. Thesystem of claim 9, wherein the liner has an outer diameter greater thanor equal to 6.0 in.
 14. The system of claim 9, further comprising a heattrace coupled to the production string, wherein the heat trace isconfigured transfer thermal energy to hydrocarbons flowing through theproduction string.
 15. The system of claim 9, further comprising achemical injection line coupled to the production string, wherein thechemical injection line is configured to inject chemicals into thehydrocarbons flowing through the production string.
 16. The system ofclaim 15, wherein the chemical injection line has a downhole injectionend positioned adjacent the outlet end of the pump.
 17. The system ofclaim 9, wherein the tailpipe has a central axis, an uphole end coupledto the inlet end of the pump and a downhole end distal the pump, whereinthe downhole end of the tailpipe comprises an intake, wherein thecentral axis of the tailpipe at the intake is oriented an angle βbetween 85° and 90° measured upward from vertical.
 18. The system ofclaim 17, wherein the pump has a central axis oriented at an angle αbetween 60° and 90° measured downward from vertical.
 19. The system ofclaim 18, wherein the angle β is between 89° and 90°; and wherein theangle αis about 75°.
 20. The system of claim 9, wherein the tailpipecomprises a slotted joint proximal the inlet end of the pump.
 21. Thesystem of claim 9, wherein the tailpipe includes a gas exhaust portproximal the pump, wherein the gas exhaust port is configured to flowgas separated from a fluid flowing through the tailpipe.
 22. A methodfor producing hydrocarbons from a wellbore having a substantiallyhorizontal portion traversing a formation comprising sand, the methodcomprising: (a) determining a maximum grain size of the sand in theformation; (b) inserting a liner into the substantially horizontalportion of the wellbore, wherein the liner has a longitudinal axis and aplurality of circumferentially spaced elongate slots, wherein each slotis oriented parallel to the longitudinal axis and has a width that is atleast 95% of the maximum grain size of the sand; (c) coupling a tailpipeto an inlet end of a pump; (d) coupling a production string to an outletend of the pump; and (e) positioning the pump and the conduit in theliner after (d).
 23. The method of claim 22, wherein (e) comprises: (e1)orienting a central axis of the pump at an angle α between 60° and 90°measured downward from vertical; (e2) orienting an intake of thetailpipe distal the pump at an angle β between 85° and 90° measuredupward from vertical.
 24. The method of claim 23, further comprising:(f) operating the pump to simultaneously produce hydrocarbons and atleast some of the sand in the formation to the surface.
 25. The methodof claim 24, wherein (f) comprises: (f1) increasing drawdown of thewellbore by no more than 1-4 pounds per square inch per hour until sandis produced from the wellbore; and (f2) maintaining a near constantdrawdown of the wellbore until sand produced from the wellborestabilizes.
 26. The method of claim 25, further comprising repeating themethod of claim 25 until a sand-cut of 1% to 25% is produced from thewellbore.